As refiners are regulated towards producing cleaner, lower-sulfur transportation fuels from heavier or poorer-quality crudes, amount of pet coke and refinery resides generated is increasing but their market decreasing. At the same time, the low sulfur product specifications also drive a significant increase in demand for hydrogen. A potentially economical option for a refiner is to use these heavy and low value hydrocarbon stocks to generate hydrogen and utilities (power and steam), either used by the refinery or sold in a deregulated electric power market. In addition, these hydrocarbon feedstocks can also be converted to sulfur-free liquids, such as transportation fuels, dimethyl ether (DME), methanol, via Fisher-Tropsch process. Upgraded F-T liquids are zero sulfur, paraffinic hydrocarbons that can be classified as ultra-clean transportation fuels and be used as a blending stock to assist refiners in meeting ultra low sulfur diesel specifications.
It was reported that there are 35 refineries in the US that have greater than 1,000 TPD Coking capacity (D. Gray and G. Tomlinson, “Potential of Gasification in the U.S. Refining Industry”, U.S. Department of Energy Contract No.: DE-AC22-95PC95054, Jun. 1, 2000). A total of almost 95,000 TPD of Pet coke is produced in these 35 refineries. Total U.S. coke production for 1999 was 96,200 tons; therefore, these 35 refineries represent over 98 percent of production.
The key for the conversion of low-value feedstock to high value fuels is gasification. Integrated gasification combined cycle (IGCC) processes, as shown in U.S. Pat. No. 4,946,477, convert heavy refinery residue and/or coal into a mixture of H2 and CO (syngas) to produce power and/or steam, and optionally also produce hydrogen. “Combined Cycles” use both gas and steam turbine cycles in a single plant to produce electricity with high conversion efficiencies and low emissions. In an IGCC plant, coal or coke is gasified in a reaction vessel. The hot gaseous effluent from gasification (referred to as “raw syngas”) is cooled, cleaned and, expanded through a gas turbine for power generation. Waste heat from the gas turbine and from gas cleaning and gasification processes is used to raise high-pressure steam for additional electricity generation.
Hydrocarbon synthesis units, or gas to liquid (GTL) units, convert syngas to useful synthetic hydrocarbon products. The term hydrocarbon synthesis unit, as used in this application, can be various processes known in the art for conversion of syngas into synthetic hydrocarbon products. The hydrocarbon synthesis units may comprise synthesis reactors, liquid/vapor separation systems, product upgrading units, such as hydrocracking, and/or other processes. Hydrocarbon synthesis processes may include Fischer-Tropsch (F-T) processes, or other gas to liquid processes (GTL), known to one skilled in the art.
Syngas produced from petcoke or coal is relatively deficient of H2, that is, the H2/CO ratio of the syngas is low (usually <1). This ratio is too low for the syngas to be utilized as a feed stocks to a F-T based GTL process. For instance, a F-T process based on certain catalyst, or a methanol production process requires a syngas with a H2/CO ratio of about 2.0. Either adding H2-rich stream to the syngas or removing H2 from the syngas can adjust the H2/CO ratio. It is desirable to develop processes that efficiently use heavier/poor quality feedstocks while still supplying higher H2/CO ratio syngas to hydrocarbon synthesis units.
Refineries use hydrotreating as a key step to produce low sulfur fuels, such as gasoline and diesel. Hydrotreators (hydrotreating reactors) treat the petroleum feedstock catalytically in the presence of an excess of hydrogen to remove sulfur, nitrogen, metals, etc, from the feed. Higher purity and partial pressure of hydrogen result in higher quality refinery products with the same reaction system. However, it is difficult to maintain the high purity levels of hydrogen in the hydrotreator due to a buildup of inert gases in the system. To remove the inert gases, a portion of the recycle gas is purged to continuously remove inert gases from the hydrotreating system. The hydrogen required by the reactions is supplied through a make up stream that usually has a high H2 content. The more make up stream is used, and the more recycle gas is purged, the higher the H2 purity in the hydrotreating reactor. Since the recycle gas is high in hydrogen content, purging will result in significant hydrogen losses to the process. Thus, it is desirable to reject non-hydrogen components in the purge-gas stream while recapturing the contained hydrogen. It is also desirable to extract value, such as the heating value, from the non-hydrogen components of the purge stream. A selective separation unit, such as a H2 selective membrane can achieve such objectives.
There are several important separation operations that are critical to achieve the conversion of the low value feedstocks to high value fuels, chemicals and power with very low emissions. These are dictated by the following characteristics of such an integrated complex:                Syngas produced from heavy feedstocks has low H2/CO ratio (<1), too H2-lean to be used as a FT/GTL or methanol plant feed gas.        Refinery hydroprocessing units need higher purity make-up H2 for improved efficiency in reaching low sulfur content in fuel products. At least a part of gaseous stream of these units need to be purified, including primarily sulfur removal, light hydrocarbon rejection and H2 purity upgrading.        The inert or by-product gases from a GTL and a chemical production process need to be rejected while not losing valuable feed stock such as H2 and CO.        Relatively high purity H2 is required for FT liquid upgrading via mild hydrocracking. Such H2 is not readily available from the heavy hydrocarbon gasification process.        
Utilizing membrane and PSA separation schemes can achieve more efficient integration of IGCC, GTL and refining processes and saves on capital and operating expenditures related to various separation operations.
For refinery hydroprocessing units, an increased purge of recycle gas can be practiced by using a membrane permeator to only purge the light hydrocarbons, especially methane while not losing H2. For a GTL plant, a desired feed gas composition can be obtained by either removing H2 from raw syngas or by blending H2-rich gas, such as the gas from the membrane permeator, to the raw syngas.
For refining hydroprocessing unit and GTL product upgrading/hydrocracking units, higher purity H2 is provided. The high purity H2 make-up and increased purge allow a higher H2 partial pressure in the reactors, and therefore a better reaction process efficiency.
Cost for sulfur removal can be reduced by sharing an acid gas removal unit (AGR) between gasification and refining units.
Thus, it is desirable to develop processes that maximize production of high value liquids, minimizes the output of heavy residue while increasing hydrotreating efficiency of refinery hydroprocessing units (including hydrotreating and hydrocracking operations). Such objectives can be achieved by a rational utilization of H2 in a refinery with gasification and GTL units via gas separation using membrane and other means.